Fortnightly - IRRhttps://www.fortnightly.com/tags/irr
enTurning Energy Inside Outhttps://www.fortnightly.com/fortnightly/2013/03/turning-energy-inside-out
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Amory Lovins on negawatts, renewables, and neoclassical markets.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Michael T. Burr</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Michael T. Burr</b> is <i>Fortnightly’s</i> Editor-in-Chief. Email him at <a href="mailto:burr@pur.com">burr@pur.com</a></p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - March 2013</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="https://www.fortnightly.com/sites/default/files/1303-FEA1-ABL.jpg" width="1193" height="910" alt="Amory Lovins" title="Amory Lovins" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>The name “Amory Lovins” means different things to different people in the energy industry.</p>
<p>To some executives, the name means “tree hugger.” For about three decades, the co-founder of the <span style="line-height: 1.538em;">Rocky Mountain Institute (RMI)</span><span style="line-height: 1.538em;"> has acted as a champion for green energy development and a critic of Big Oil—and big utilities. Since the energy crisis of 1973, he’s advocated what he calls the “soft” energy path—less reliance on Big Energy with its centralized power plants, landscape-spanning transmission lines, and hard-won fossil fuels, and more reliance on smaller, locally sourced renewables, conservation, and efficiencies driven by competitive market forces. And in the 1970s and ’80s, he argued against nuclear energy, largely on the basis that its development would spur weapons proliferation.</span></p>
<p>To many outside the industry, however, the name Lovins means “visionary.” In 2009, for example, <i>Time</i> magazine named him one of the world’s most influential people, saying that he “had the solution to the energy problem in 1976,” and that his ideas about conservation and renewable energy “have become accepted wisdom.”</p>
<p>Granted, those words in <i>Time</i> were written by Carl Pope, executive director of the Sierra Club. But as a general matter, many of the facts seem to bear him out. And as it happens, <i>Public Utilities Fortnightly’s</i> archive includes a record of those facts.</p>
<p>In March 1985—28 years ago this month—this magazine published Lovins’s article titled “<a href="http://www.fortnightly.com/saving-gigabucks-negawatts" target="_blank">Saving Gigabucks with Negawatts</a>.”<strong><sup><a href="http://www.fortnightly.com/fortnightly/2013/03/turning-energy-inside-out/page/0/5" title="1. “Saving Gigabucks with Negawatts,” Amory B. Lovins, Public Utilities Fortnightly, March 21, 1985.">1</a></sup></strong> That article represents the earliest known publication of the term “negawatt”—a word that’s entered the industry lexicon.<strong><sup><a href="http://www.fortnightly.com/fortnightly/2013/03/turning-energy-inside-out/page/0/5" title="2. The Fortnightly article wasn’t the first public use of the term; that happened a few months earlier, when Lovins delivered a presentation at the NARUC Annual Meeting on the same topic.">2</a></sup></strong> More importantly, it described a future in which both supply and demand-side resources would be bid into competitive electricity markets; buildings would produce as much energy as they consume—or more; and advancing technologies and changing economics would weaken and ultimately break the longstanding correlation between economic growth and energy consumption.</p>
<p>This month we’re re-publishing <a href="http://www.fortnightly.com/saving-gigabucks-negawatts" target="_blank">Lovins’s 1985 article</a> at Fortnightly.com. The article makes remarkable reading today, in part because it was so prescient; much of what Lovins predicted has indeed come to pass. However, what’s even more remarkable is that the article actually still applies today, almost three decades later. With some editing—changing some details—it still presents a solid analysis of industry trends that are playing out right now.</p>
<p>Lovins spoke with <i>Fortnightly</i> in February about those trends. That conversation, in edited form, follows here. And in an accompanying article, <a href="http://www.fortnightly.com/fortnightly/2013/03/scratching-surface" target="_blank">Lovins offers his retrospective view</a> on “Saving Gigabucks with Negawatts,” in the context of RMI’s current focus.</p>
<p><b>Fortnightly:</b> In your 1985 article, you’d proposed a “neoclassical competitive marketplace for energy services,” versus what then was an “imperfect fuel bazaar, satisfying no condition of the ideal free market.” Since then the utility industry has developed competitive electricity markets in fits and starts, and only in some locations, with varying degrees of success. It would seem the imperfect bazaar still prevails. Why are we still here?</p>
<p><b>Lovins:</b> Where we are is messy but improving. Competitive markets cover about 60 percent of the nation’s electricity demand—almost everything but the Southeast and much of the intermountain West. Nearly all the rest is covered by RTOs or equivalents. In the Northeast, PJM, and MISO—30-odd states—negawatts can now be bid into what formerly were only supply-side auctions. And in 15 states, with six more pending, utilities are no longer rewarded for selling you more electricity.</p>
<p>We’ve made progress, and the results in states that have adopted decoupling and shared savings speak for themselves. Those utilities have better value and lower risk, and they can provide better service, often at lower cost, because they’re rewarded—not penalized—for doing the cheapest things first.</p>
<p>Arguably just the building codes recently entering force in half the states suffice to flatten national electricity demand growth to about zero. And indeed electricity use seems to be drifting down, not up, even during an economic recovery, because electric intensity (kWh used per dollar of real GDP) is dropping steadily—not evenly across the country, but in total. This pressure should gradually cause the electric industry, like the gas industry earlier, to push harder for decoupling. And decoupling, combined with shared savings, should then produce such dramatic financial, cultural, and behavioral change in the industry that modern, least-cost, efficiency-centric efforts would become the new center of gravity.</p>
<p>John C. Fox, my predecessor as chairman of RMI, led PG&amp;E’s demand-side efforts when they were the biggest and best in the world. In 1992, PG&amp;E invested $170-odd million to help customers save electricity cheaper than it could be produced even by existing plants. This yielded nearly $400 million in present-value benefits, which the CPUC allocated 89 percent to customers as lower bills and 11 percent to the utility. The initial investment was amortized to all customers over many years, just as it would’ve been for a new power station, but since efficiency was cheaper, it was bought first. The 11 percent reward went straight to the utility’s bottom line. It totaled more than $40 million that year—PG&amp;E’s second-biggest source of profit after the Diablo Canyon deal.</p>
<p>Fox reported that if you add $40 million to the bottom line at no risk or cost to the company, your CEO will call you every week to ask if there’s anything you need, and all the smartest people in the company will want to come and work in your division to advance their careers. Aligning customer interests with company interests profoundly affects culture and behavior.</p>
<p>That story has a sharper point today. The industry faces big catch-up investments on old infrastructure, along with reliability and security issues, environmental cleanup, and other investments that are more necessary than productive. But upward rate pressure plus stagnant or falling sales could shrink the domain of financial stability. Some financial analysts [draw] a disturbing analogy to how quickly the business model of newspapers went upside-down, and to the large sensitivities of many electric utilities’ EBITDA and net earnings to the decline in revenue observed in the Great Recession a few years back. From this perspective, buying small, fast, granular resources—rather than big, slow, lumpy ones—could be an important tool for financial risk management.</p>
<p><b>Fortnightly:</b> By “small, fast, granular resources,” are you talking about distributed generation and demand response?</p>
<p><b>Lovins: </b>Yes, and energy efficiency, though modern renewables like windpower and photovoltaics (PV) get more press. In 2011 alone, non-hydro renewables got $225 billion of private investment worldwide and added 84 GW of capacity. Renewables including big hydro have added half of the world’s new capacity starting in 2008, the majority lately in developing countries, and now make a fifth of the world’s electricity.</p>
<p>But hidden in those numbers is a game changer like we haven’t seen since Edison’s day. Recently I visited a Chinese factory that was producing two and a half gigawatts of solar cells every year. The means of making electricity has already shifted to a scalable, mass-produced, manufactured product with a steep learning curve. Creating this industry’s basic asset is now much more like the way we make microchips, cell phones, and computers than it is like the specialized, massive, cathedral-like edifices with decade-long lead-times that have dominated our investments and balance sheets, yet now lack a business case.</p>
<p>Thus core technologies have been transformed in type, scale, speed, and accessibility to many market actors. Close behind those technologies is a swarm of new business models, revenue models, and regulatory models. The electricity sector—the most capital-intensive, complex, and vital part of the economy—is facing more numerous, diverse, and profound disruptions than any other sector, as 21st-century speed collides with 20th- and even 19th-century rules, institutions, and cultures. That’s why my colleagues at RMI have launched the Electricity Innovation Lab (e-Lab)—a multi-year, multi-stakeholder effort in rapid mutual learning to figure out together the contours and many of the details of the next electricity industry.</p>
<p><b>Fortnightly:</b> History shows that change happens fastest in this industry when it serves utilities’ interests, rather than threatens them. How can utilities be convinced they should support this change, rather than fight it?</p>
<p><b>Lovins:</b> First they need to understand its speed and scale. For example, a utility might consider PV its least-plausible competitor among modern renewables, because it’s the costliest major renewable technology. Yet in April 2012, more than 4 GW of PV generation cleared the California auction at a busbar cost of $89/MWh in levelized 2012 dollars—cheaper than power from a new gas-fired combined-cycle plant. To be sure, that’s with the benefit of a 30-percent solar tax credit, which expires in 2016. But by that time you’ll get the same result without the tax credits—as Germany proved last year by cutting its average cost for installed PV systems to half the U.S. average. Or you can get competitive, unsubsidized PV today by counting some of the distributed benefits that astute market actors are starting to exploit, but that most market structures fail to recognize. For more on this, see RMI’s 2002 book, <i>Small Is Profitable</i>.<strong><sup><a href="http://www.fortnightly.com/fortnightly/2013/03/turning-energy-inside-out/page/0/5" title="3. E. Kyle Datta, et al., Small is Profitable, Rocky Mountain Institute, 2002.">3</a></sup></strong></p>
<p>The second observation is that in about 20 states, companies like SunEdison, Sun Run, Sungevity, SolarCity, and their rivals will happily come to your house, install solar power on your roof with no money down, and beat your utility bill. There are at least a half-dozen ways an incumbent can respond to such insurgents. It can ignore them; fight them; try to tax or block them; finance them; buy them; incorporate their products as its own branded offering; become an open-source integrator for all qualified offerings; or several other possibilities. But among all responses, playing ostrich isn’t a good one.</p>
<p>This sort of basic challenge to the traditional utility model does focus the mind wonderfully, and calls for an unprecedented level of thoughtfulness and creativity in figuring out both competitive and coopetition models—as well as the new regulatory models that come with them.</p>
<p>But the challenge is more fundamental than it might appear, on at least two levels. First, the old revenue model is broken. California and the U.S. Army, among others, have set goals for net-zero-energy homebuilding, so that new homes will produce at least as much electricity as they use during the course of each year. Well, if you’re charging customers for kilowatt-hours, but their net use of kWh over the year is zero, then they pay you zero net revenue, even though both you and the home are swapping valuable services for which you should both be properly compensated. <i>(See <a href="http://www.fortnightly.com/fortnightly/2013/03/law-unintended-consequences" target="_blank">“</a></i><a href="http://www.fortnightly.com/fortnightly/2013/03/law-unintended-consequences" target="_blank"><i>The Law of Unintended Consequences</i></a><i><a href="http://www.fortnightly.com/fortnightly/2013/03/law-unintended-consequences" target="_blank">,” </a>this issue, page 44)</i>.</p>
<p>That’s the kind of trouble you get into if, as Walt Patterson reminds us, you treat electricity as a commodity when it’s really an infrastructure.</p>
<p>Second, utilities as we know them are the folks we’ve always hired to keep the lights on and the motors humming. But customers have expanding choices. Utilities that annoy their customers, by price or behavior, risk the sort of bypass that drove many phone customers to abandon the landline and use only cell phones, sometimes with different service providers. The difference is that the cell phone business still relies on a lot of the old copper and fiber assets, whereas electricity customers might bypass the grid entirely. The entrepreneurs who put that competitive solar power on your roof with no money down can provide a portfolio of other equally unregulated products, like efficiency, demand response, storage, and so on, that could ultimately add up to a virtual utility providing the same services that utilities now provide—quite possibly with lower cost and greater reliability and resilience.</p>
<p><b>Fortnightly:</b> I’ve been hearing a lot of people use that word “resilience” lately, especially in the wake of Superstorm Sandy.</p>
<p><b>Lovins:</b> That’s right. “Resilience” is another hot trend moving us toward a more efficient, diverse, distributed, and renewable power system. Thirty-one years ago, RMI published a book titled <i>Brittle Power: Energy Strategy for National Security</i>,<strong><sup><a href="http://www.fortnightly.com/fortnightly/2013/03/turning-energy-inside-out/page/0/5" title="4. Lovins, Amory B. and Hunter L., Brittle Power: Energy Strategy for National Security, Brick House Publishing, 1982.">4</a></sup></strong> with a foreword by former CIA Director Jim Woolsey and Admiral Tom Moorer, who was chairman of the joint chiefs under President Nixon. That book remains the definitive unclassified work on domestic energy critical infrastructure. It found that power systems were under attack daily around the world and that a handful of people could turn off three-fourths of the oil and gas supply to the Eastern states without leaving Louisiana—then keep it down for a year. Electricity systems were even more vulnerable—and that was before the Internet was deployed in an extraordinarily insecure way to control power systems, creating new and even scarier types and levels of vulnerability, whose exploitation could black out many parts of the country and prevent recovery.</p>
<p>Having served on the Defense Science Board Task Force that surfaced this issue in 2006 through 2008, I’m a little surprised every morning that the lights are still on, because much of the industry still hasn’t taken precautions to secure the electric grid. Yet this vulnerability to grave and potentially economy-shattering disruption is unnecessary and correctable. The most fundamental way to correct it is to shift the architecture of the grid. We can take advantage of small, fast, granular resources on both the supply and demand sides by reorganizing the grid into netted, islandable microgrids. These normally exchange power, but can stand alone at need, disconnecting fractally and reconnecting seamlessly so that critical loads are served by local resources, until wider interconnections are restored. And the more distributed the generation, the greater the reliability, since 98 to 99 percent of U.S. power failures originate in the grid.</p>
<p><b>Fortnightly: </b>We’ve seen a lot of interest in microgrids lately. But so far I’m only aware of some fairly small pilot projects. Is this technology pie in the sky, or is it real today?</p>
<p><b>Lovins: </b>Denmark has been piloting such a cellular grid over significant areas. Professor Abe at Tokyo University and a Japanese industry consortium have even developed a “digital grid,” connected by smart, asynchronous inverters that act as routers for electricity—delivered in packets labeled by their price, origin, and impact. Cuba—which we can learn from even if we wouldn’t want to live there—combined netted, islandable microgrids with efficiency and distributed generation to go from 224 serious blackout days in 2005 to zero in 2007. Then in 2008, those microgrids sustained vital services while two hurricanes in two weeks shredded the eastern grid. Some remaining dependence on geriatric, Soviet-era oil plants blacked out 5 million people in greater Havana last September. But in general the change has had a stunning benefit for reliability.</p>
<p>Resilient design can make cascading, large-scale, long-term grid failures impossible by design—rather than inevitable by design, as they are now. The Pentagon has adopted this resilient approach for its own power supply at its bases to ensure its own mission continuity, because they need their stuff to work. Of course so do the rest of us, the people they’re defending. As we rebuild broken infrastructure, Hurricane Sandy should inform us that designing for resilience is no longer a luxury. The security it brings, not just to our country but to each customer, is valuable and highly marketable.</p>
<p><b>Fortnightly:</b> How is it marketable?</p>
<p><b>Lovins:</b> I’ve talked to homebuilders about the notion of putting in every new home certain specially colored sockets—say, orange—that don’t go off in a power outage, and to which you could connect things like your refrigerator, freezer, computer, and communication systems. The number of orange sockets could later rise as, for example, PV gets cheaper and the array on your roof expands. Homebuilders agree that even initially this form of household security and insurance would be a very marketable feature. Many of the big merchant homebuilders already offer integrated rooftop solar power systems as an option, and sometimes even as standard equipment. Had that already been widely installed in the Sandy-damaged area, it could’ve saved a great deal of misery and disruption.</p>
<p>The inherent vulnerability of today’s electric grid to natural disaster and solar storms, and its physical and cyber vulnerability to attack, are moving grid security and resilience rapidly up many customers’ agenda. Microgrids offer a vital opportunity for the electricity industry to anticipate customers’ needs while ensuring its own technical, political, and financial resilience.</p>
<p><b>Fortnightly:</b><b> </b>The state of Connecticut is actively promoting microgrid development in the wake of recent extended outages. Do you see a need for regulatory or legislative mandates to drive the industry toward building microgrids?</p>
<p><b>Lovins:</b> My colleagues and I proposed microgrids in Connecticut before Sandy. Especially after Sandy, state regulators and FERC are paying careful attention. Cybersecurity and resilience were a major theme at NARUC’s February national meeting under Phil Jones’s leadership. Policies might spread that, for example, make islandability the default design for distributed generators, rather than, as now, often being prohibited by local practice. Utilities can change that local practice themselves, because often it’s not the result of regulation, but of outmoded assumptions.</p>
<p>Recently I toured a major public building that was just completing installation of a large rooftop PV array. This building was also the principal local tornado shelter. I asked the building operator whether the PV array could work without the grid—powering the building, at least in the daytime, right through a disaster. The operator said, “We have modern inverters with IEEE-1547-compliant islandability features, but we can’t activate them because our utility forbids the practice.” It turned out the utility wasn’t conversant with the industry-consensus standard, and still clung to the old belief that to protect its linemen, inverters must be solely grid-excited, so if the grid goes down they go too.</p>
<p>IEEE 1547 standards provide automatic isolation and protection for linemen. It’s entirely within the purview of utilities to change their rules; I don’t think it would even require commission approval, but I’m sure commissions would recognize the merit and public-safety case if they were asked.</p>
<p>This is a time for utility leadership to get ahead of the curve on this increasing issue of public safety, customer continuity, and national security. We needn’t wait for Congress or any regulatory body to tell us this approach can make sense and make money.</p>
<p><b>Fortnightly:</b> Generally state regulators don’t tell utilities what to do. Rather they respond to utilities’ filings. So it seems likely the impetus will have to come from customers and utilities themselves, rather than regulators. What factors will drive that demand? Is it simply a matter of customers’ losing patience over outages? Or is it more complex than that?</p>
<p><b>Lovins:</b> Leadership can come from many directions. SDG&amp;E found the microgrid at the University of California San Diego campus to be extremely useful when a wildfire took down a power line, and the campus was able to switch quickly from being a large net importer of power to a net exporter. The design can come from a customer or a utility, just as a better way of doing business—like the fine work by Susan Story and her team at Southern Company Services’ in creating great customer value, including radically better outage response, through smart meters and IT integration. In fact, such grid intelligence is a logical step toward microgrids.</p>
<p>There’s an even bigger strategic opportunity here. John C. Fox, whom I mentioned earlier, led the Delta Project at PG&amp;E and two later experiments at Ontario Hydro, illustrating what I’d call the “inside-out utility.” Those utilities traditionally were dominated by their generating side. They’d extrapolate demand, then build generators and wires to meet it. But these experiments instead focused first on the part of the company that was investing the most—distribution. They picked a distribution area where they planned to expand, upgrade, or modernize substations, feeders, or other costly assets, and they examined the end-use structure in that neighborhood. How much of the peak load was coming from commercial lighting, from residential water heating, and so on? With that information, demand-side investments could be aimed like a rifle, not a shotgun, specifically to reduce those loads in that neighborhood, and thus defer or avoid building costly distribution infrastructure. If that didn’t suffice, then the utility could refurbish distribution or even consider distributed generation. The surprise was that by starting at the distribution planning area and working back toward generation, they found that customer needs could be reliably met without expanding T&amp;D—with about an order of magnitude lower capital investment.</p>
<p>In today’s tough investment environment, that’s an extremely important lesson to recall, test, and spread around. And of course it’s fully consistent with the focus on resilient distribution architecture, with a least-cost strategy emphasizing the best buys first, notably end-use efficiency and demand response.</p>
<p><b>Fortnightly:</b> What efforts at RMI do you see as most promising for bringing about the neoclassical competitive marketplace you described in your 1985 article?</p>
<p><b>Lovins:</b> In electricity, our flagship effort to understand and help create that future is the e-Lab, whose three dozen members have launched some important research initiatives.</p>
<p>You can’t understand the electricity system in isolation from the sectors it serves. Nearly three-fourths of U.S. electricity powers buildings. The rest runs industry. In <i>Reinventing Fire</i>,<b><sup><a href="http://www.fortnightly.com/fortnightly/2013/03/turning-energy-inside-out/page/0/5" title="5. Amory Lovins, Reinventing Fire: Bold Business Solutions for the New Energy Era, Chelsea Green Publishing, 2011.">5</a></sup></b> we showed how U.S. buildings could triple or quadruple their energy productivity with a 33-percent internal rate of return (IRR), while industry could double its energy productivity with a 21-percent IRR. These things can be achieved by 2050 if efficiency’s average national rate of adoption ramps up over 20 years to the levels already achieved by 2009 in the Pacific Northwest—which seems ambitious but plausible. Altogether, we showed how to run a 2.6-fold bigger economy in 2050 with no oil, coal, or nuclear energy, and with one-third less natural gas, 82 to 86 percent less carbon emissions, and a $5 trillion lower cost in net present value, counting all externalities at zero. We showed this will require no new inventions nor acts of Congress, but rather will be led by business for profit—$5 trillion being ample inducement. And we found that an 80-percent renewable, highly reliable and resilient, half-distributed electricity system could cost essentially the same as business-as-usual.</p>
<p>Dwight D. Eisenhower said, “If a problem can’t be solved, enlarge it.” You expand the problem’s boundaries until they embrace everything the solution requires. You integrate the sectors, including buildings, industry, and transportation, and you innovate not just through technology and public policy, but also in design and strategy.</p>
<p>You also use integrative design—optimizing a whole building, factory, or vehicle as a system, not components in isolation, to achieve multiple rather than single benefits. This approach makes large energy savings often cheaper than small savings, turning diminishing returns into expanding returns. That’s the biggest game changer on the demand side. But also, integrating across sectors makes it easier to solve the electricity and automobile problems together than [it would be to solve them] separately. As breakthrough auto designs—some entering mass production this year in Germany—make electric automobiles affordable with great competitive advantage, their controllable off-peak loads and distributed storage can help integrate variable wind and solar power sources into the grid.</p>
<p>There’s increasing evidence, too, that with a properly integrated portfolio of renewables—diversified by type and location, properly forecasted, and artfully combined with flexible supply- and demand-side resources on the grid—the storage and backup required for stable and reliable power supply could well be less than business-as-usual scenarios need to manage the intermittence of large thermal stations.</p>
<p>Looking at it symmetrically, if we worry about firming, balancing reserves, and integration for variable renewables, then we should also calculate the same costs for traditional generating assets. Reserve margin, spinning reserve, and redundant transmission capacity aren’t free either.</p>
<p>We’re moving into an era where all ways to make or save energy will get to compete fairly, at honest prices, regardless of their type, technology, size, location, and ownership.</p>
<p> </p>
<h4>Endnotes:</h4>
<p>1. “<a href="http://www.fortnightly.com/saving-gigabucks-negawatts">Saving Gigabucks with Negawatts</a>,” Amory B. Lovins, <i>Public Utilities Fortnightly</i>, March 21, 1985.</p>
<p>2. The <i>Fortnightly</i> article wasn’t the first public use of the term; that happened a few months earlier, when Lovins delivered a presentation at the NARUC Annual Meeting on the same topic.</p>
<p>3. E. Kyle Datta, et al., <i><a href="http://www.smallisprofitable.org/ReadTheBook.html" target="_blank">Small is Profitable</a>, Rocky Mountain Institute, 2002.</i></p>
<p>4. Lovins, Amory B. and Hunter L., <i><a href="http://www.rmi.org/Knowledge-Center/Library/S82-03_BrittlePowerEnergyStrategy" target="_blank">Brittle Power: Energy Strategy for National Security</a>, Brick House Publishing, 1982.</i></p>
<p>5. Amory Lovins, <a href="http://www.amazon.com/Reinventing-Fire-Business-Solutions-Energy/dp/1603583718" target="_blank"><i>Reinventing Fire: Bold Business Solutions for the New Energy Era</i></a>, Chelsea Green Publishing, 2011.</p>
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<a href="/tags/amory-lovins">Amory Lovins</a><span class="pur_comma">, </span><a href="/tags/rocky-mountain-institute">Rocky Mountain Institute</a><span class="pur_comma">, </span><a href="/tags/green-energy">Green energy</a><span class="pur_comma">, </span><a href="/tags/carl-pope">Carl Pope</a><span class="pur_comma">, </span><a href="/tags/sierra-club">Sierra Club</a><span class="pur_comma">, </span><a href="/tags/negawatt">negawatt</a><span class="pur_comma">, </span><a href="/tags/saving-gigabucks-negawatts">Saving Gigabucks with Negawatts</a><span class="pur_comma">, </span><a href="/tags/demand-side-management-0">Demand-side management</a><span class="pur_comma">, </span><a href="/tags/dsm">DSM</a><span class="pur_comma">, </span><a href="/tags/rmi">RMI</a><span class="pur_comma">, </span><a href="/tags/rto">RTO</a><span class="pur_comma">, </span><a href="/tags/pjm">PJM</a><span class="pur_comma">, </span><a href="/tags/miso">MISO</a><span class="pur_comma">, </span><a href="/tags/decoupling">decoupling</a><span class="pur_comma">, </span><a href="/tags/shared-savings">shared savings</a><span class="pur_comma">, </span><a href="/tags/john-c">John C</a><span class="pur_comma">, </span><a href="/tags/fox">Fox</a><span class="pur_comma">, </span><a href="/tags/pge">PG&amp;E</a><span class="pur_comma">, </span><a href="/tags/cpuc">CPUC</a><span class="pur_comma">, </span><a href="/tags/diablo-canyon">Diablo Canyon</a><span class="pur_comma">, </span><a href="/tags/ebitda">EBITDA</a><span class="pur_comma">, </span><a href="/tags/windpower">windpower</a><span class="pur_comma">, </span><a href="/tags/photovoltaics">Photovoltaics</a><span class="pur_comma">, </span><a href="/tags/pv">PV</a><span class="pur_comma">, </span><a href="/tags/electricity-innovation-lab">Electricity Innovation Lab</a><span class="pur_comma">, </span><a href="/tags/elab">eLab</a><span class="pur_comma">, </span><a href="/tags/sunedison">SunEdison</a><span class="pur_comma">, </span><a href="/tags/sun-run">Sun Run</a><span class="pur_comma">, </span><a href="/tags/sungevity">Sungevity</a><span class="pur_comma">, </span><a href="/tags/solarcity-0">SolarCity</a><span class="pur_comma">, </span><a href="/tags/walt-patterson">Walt Patterson</a><span class="pur_comma">, </span><a href="/tags/resilience">Resilience</a><span class="pur_comma">, </span><a href="/tags/brittle-power">Brittle Power</a><span class="pur_comma">, </span><a href="/tags/jim-woolsey">Jim Woolsey</a><span class="pur_comma">, </span><a href="/tags/tom-moorer">Tom Moorer</a><span class="pur_comma">, </span><a href="/tags/defense-science-board-task-force">Defense Science Board Task Force</a><span class="pur_comma">, </span><a href="/tags/microgrid">Microgrid</a><span class="pur_comma">, </span><a href="/tags/professor-abe">Professor Abe</a><span class="pur_comma">, </span><a href="/tags/tokyo-university">Tokyo University</a><span class="pur_comma">, </span><a href="/tags/cuba">Cuba</a><span class="pur_comma">, </span><a href="/tags/islandable">islandable</a><span class="pur_comma">, </span><a href="/tags/pentagon">Pentagon</a><span class="pur_comma">, </span><a href="/tags/sandy">Sandy</a><span class="pur_comma">, </span><a href="/tags/orange-socket">orange socket</a><span class="pur_comma">, </span><a href="/tags/connecticut">Connecticut</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/naruc">NARUC</a><span class="pur_comma">, </span><a href="/tags/phil-jones">Phil Jones</a><span class="pur_comma">, </span><a href="/tags/ieee-1547">IEEE 1547</a><span class="pur_comma">, </span><a href="/tags/sdge">SDG&amp;E</a><span class="pur_comma">, </span><a href="/tags/susan-story">Susan Story</a><span class="pur_comma">, </span><a href="/tags/southern-company">Southern Company</a><span class="pur_comma">, </span><a href="/tags/delta-project">Delta Project</a><span class="pur_comma">, </span><a href="/tags/ontario-hydro">Ontario Hydro</a><span class="pur_comma">, </span><a href="/tags/reinventing-fire">Reinventing Fire</a><span class="pur_comma">, </span><a href="/tags/internal-rate-return">Internal rate of return</a><span class="pur_comma">, </span><a href="/tags/irr">IRR</a><span class="pur_comma">, </span><a href="/tags/eisenhower">Eisenhower</a><span class="pur_comma">, </span><a href="/tags/integrative-design">integrative design</a> </div>
</div>
Fri, 01 Mar 2013 02:20:17 +0000meacott16479 at https://www.fortnightly.comSolar Emergencehttps://www.fortnightly.com/fortnightly/2011/03/solar-emergence
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Models are evolving for utility-scale solar development.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Kate Bechen</p>
</div></div></div><div class="field field-name-field-import-category field-type-text field-label-inline clearfix"><div class="field-label">Category:&nbsp;</div><div class="field-items"><div class="field-item even">Business &amp; Money</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Kate Bechen</b> is an attorney and member of the energy and sustainability industry group at Michael Best &amp; Friedrich LLP. Email her at <a href="mailto:klbechen@michaelbest.com">klbechen@michaelbest.com</a>.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - March 2011</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>Each year U.S. demand for solar energy increases, even during the recent recession. Demand comes from all sectors: residential markets, driven by residential users’ interest in going green and the availability of residential tax credits; as well as commercial-scale and utility-scale green energy programs.</p>
<p>The residential market is expected to continue increasing, especially as new financing models become more common. For example, leases and power purchase agreements allow residential consumers to consume solar energy without the large up-front costs associated with installing a solar array. Obviously, this type of financing model requires the residential consumer’s utility to offer such options, but some markets are seeing demand for such arrangements. Further, technological development in the portability of solar arrays would allow homeowners to move their PV panels with them to a new home when relocating. This would give owners greater confidence that they’d be able to gain the full value from their investments, even if they sell their home to a buyer who doesn’t value solar energy as highly as they do.</p>
<p>Commercial-scale projects are becoming increasingly common as businesses strive to appear more socially responsible by building or retrofitting existing structures with green technology, including solar panels. More business are also pursing LEED certification and scoring points through the installation of solar panels on buildings and parking structures.</p>
<p>But the real growth over the next few years will most likely be in utility-scale solar projects, largely due to state mandated renewable portfolio standards (RPS). With the tight financing market, project developers are struggling to meet demand from utility companies, which are required to meet state RPS policies <i>(see “Solar Power and State Mandates”)</i>. As utility-scale projects expand, they face numerous obstacles, including complexities in project financing, state and federal funding sources, and debt and private equity.</p>
<h4>Green Project Finance</h4>
<p>The demand for utility-scale solar power projects has resulted in a fair number of projects entering the development phase. According to the Solar Energy Industries Association, utility-scale projects currently under development total 23,488 MW—including both photovoltaic (PV) and thermal concentrated solar power (CSP). When compared to the 666 MW in operation and the 712 MW under construction, one might say that the future of utility-scale projects looks bright. But that isn’t the entire picture. Large-scale projects cost large amounts of money, and financing, whether from the debt or equity markets, is hard to come by as the economy recovers.</p>
<p>The installed cost of solar—PV and CSP—has decreased significantly over the last decade. That alone has proved insufficient. It’s the government incentives that make these projects attractive to developers, investors and lenders. Recent research in the U.S. and abroad reach the same conclusion: solar projects that don’t receive government subsidies are unable to compete with combined-cycle gas turbine (CCGT) plants.</p>
<p>In the U.S., government funding comes in the form of tax incentives, grants, loan guarantees and accelerated depreciation. Investment tax credits and new market tax credits encourage tax credit equity financing where investors invest in a project in exchange for the tax credits received by the project. The tax credits are then used to offset the non-project related income of the tax credit investor.</p>
<p>State programs such as RPS policies and feed-in tariffs also assist the development of the solar market. Tax-exempt bonds are issued by a municipality with interest that isn’t subject to federal taxation and, sometimes, state taxation. Tax-credit bonds allow the bond holder to claim a federal tax credit rather than receive tax-exempt interest.</p>
<p>Many programs offer loans and grants using federal stimulus money. Some such programs have been so popular that they’re oversubscribed. Some states have adopted feed-in tariffs, although the target is mostly smaller-scale residential load projects. Power purchase agreements (PPA) allow agencies, companies and individuals to purchase solar energy from a private solar company, similar to purchasing from a utility.</p>
<p>While understanding and taking advantage of government incentives is crucial, developers of solar projects understand that a long-term PPA is essential to procuring financing for any project. An interconnection agreement, construction permit and favorable internal rate of return (IRR) are also key to getting any solar project financed. Lenders typically expect certain terms and conditions in a PPA and interconnection agreement, such as assignment clauses that favor the lender. The amount of negotiation room in a PPA can differ drastically. Usually the utility has a form PPA that’s provided to all solar project developers. Often the terms differ depending upon the size of the project. Residential-scale projects might simply lack the bargaining power to demand anything but the standard terms, while larger-scale projects might have more success in negotiating price escalators and other developer-favorable terms.</p>
<p>Even with a PPA in place, developers face an uphill battle in securing funding. The pool of tax credit investors has been reduced as a result of the recession and thus the need to reduce tax liabilities. Private equity investors are still investing in solar projects, although the recent trend has been investments in larger developers and portfolios, rather than individual projects, which can make financing more difficult for smaller-scale developers. Further, we are seeing a trend toward tried and true technology and reluctance from investors when it comes to cutting-edge technology, although this is most true for debt financing. Debt markets are even more difficult. Lenders have significantly curtailed lending to projects of the size of utility-scale solar arrays, and, similar to equity investors, often give lukewarm receptions to cutting-edge technology. CSP projects need to be very large, typically a few hundred MWs, in order to be economically feasible. Securing debt financing for such a large project is typically more difficult than for a solar PV project. Tight financing has pushed utilities to adopt ownership models that give utilities control over electricity production as well as the tax benefits that accompany projects.</p>
<p>California, a state with an RPS that required utilities to purchase 20 percent of their electricity from renewable sources by 2010 (although compliance was pushed back until 2013), has demonstrated that it can work with private developers and the federal government to develop utility-scale projects. In late 2010, six utility-scale projects received fast-track approval. The projects will be built by private developers on public land, for a combined output of 2.8 GW. The projects will receive stimulus funding and also qualify for investment tax credits.</p>
<h4>Solar Business Models</h4>
<p>So what should be the role of the government in developing the solar energy market? Certainly RPS policies with solar carve-outs and state feed-in tariffs pressure utilities to purchase solar power. Stimulus money and tax credits also make solar projects more attractive to investors. If renewable energy credits were more valuable, if gas prices were higher (for a sustained amount of time) or if gas powered plants were required to purchase carbon credits, the gap between gas and solar would close. But, on the other side of the coin, if private industry were able to produce a more efficient, less costly, mobile solar array, the cost discrepancy would decrease as well.</p>
<p>While solar hardware has come a long way to be more efficient, reliable and cheaper, there isn’t as much focus on the soft costs associated with solar installations. While many incentives are available, there’s a lack of standardization in the process of locating and applying for the incentives. Further, the process is slow and document-intense, often necessitating redundant data entry. Permitting is a significant challenge to any solar project. Federal, state, county and local government authorities have jurisdiction over solar projects, which can create a permitting nightmare.</p>
<p>Even once the solar project has secured its appropriate permits, interconnection can also be an issue depending on the proximity of the project to transmission lines. There is little standardization across utility companies. Some offer a straightforward interconnection process while others, due to size, resources or lack of demand, have a cumbersome, nontransparent process.</p>
<p>Finally, companies in the solar industry need to assess whether smaller, specialized operations or vertical integration provides the greatest cost savings. Vertical integration would lend itself to utility-scale projects because the developer would manufacture and own the solar array, perhaps even design and build it as well. Specialization, with companies doing what they do best, would likely have less of a focus on utility-scale projects due to their sheer size and cost. Addressing these industry-wide soft costs could result in a material decrease in the cost of solar energy.</p>
<p>Some countries (China is a recent example) have taken steps to demonstrate that government funding should lead the development of the solar energy market. In August 2010, 13 new utility-scale solar projects were put up for bid. Seventy percent of the winning bids went to government-controlled enterprises. The bids ranged from $0.10 to $0.15 per kWh. While these rates may be adjusted depending on many factors, the projects aren’t expected to be profitable for 17 to 18 years. With this type of ROI, it’s no wonder that the winning bids went to state-controlled enterprises. Irrespective of opinions on direct state involvement, China will have significant utility-scale solar projects in the very near future—especially impressive considering that China’s first utility-scale solar project, which was put out for bids in 2009, hasn’t finished construction.</p>
<p>India may very well become a world leader as it creates one of the largest markets for CSP and, in contrast to China, the growth is largely driven by private entrepreneurship. The government recently announced that its solar energy goal is to generate 20 GW by 2022, of which 50 percent will be CSP. Both large and small companies are getting involved in CSP, learning the technology, developing working partnerships with the right companies and successfully driving down costs. With a strong economy, a large population and dedicated entrepreneurs, India may provide the strongest case for private development of the solar industry.</p>
<p>Europe has successfully created a large solar market through the use of feed-in tariffs. Feed-in tariffs involve three key provisions. First, producers are guaranteed grid access for any power they choose to sell. Second, the utility is obligated to purchase the electricity pursuant to a long-term contract. Finally, the purchase price is set by the government and is methodologically based on the cost of the energy generation.</p>
<p>Opponents of feed-in tariffs argue that competitive bidding rather than government involvement in pricing would lead to more cost effective projects. Feed-in tariffs are utilized in the U.S., but typically state feed-in tariffs only apply for small-scale producers. Ontario established a strong feed-in tariff program in 2009 and revised it further in 2010. Along with controlling the price, Ontario requires a certain percentage of the services and equipment to come from Ontario-based companies. The result has been a boom in solar projects.</p>
<p>Perhaps a common ground between direct government funding (such as the China example) or pure private research and development is the recently announced Department of Energy Solar Demonstration Zone project. In an effort to develop cost-competitive solar technologies, DOE announced that it will fund $50 million in testing and demonstration efforts. The focus is on cutting-edge solar technologies and the goal is to deploy the technology at such a scale (utility-scale projects larger than 20 MW) so as to provide meaningful operating and economic data. This DOE project is in its very early stages, so it’s hard to determine what impact it and similar initiatives might have on the development of the industry.</p>
<h4>Incentive Market</h4>
<p>Solar power has come a long way. Technological advancements have significantly decreased the installed costs of solar arrays. Tax credits and alternative financing models are encouraging the further development of residential-scale projects. Commercial-scale projects are being pursued by businesses looking to green-up their image. State RPS policies are creating a market for utility-scale projects. But, at least for today, solar projects must rely heavily on government-created incentives.</p>
<p>Tax credits, stimulus funding, grants, loan guarantees and accelerated depreciation all add to the attractiveness of a solar project, to the extent that projects that don’t rely on government incentives aren’t competitive with CCGT plants. With more states adopting new RPS policies and expanding existing ones, the need for solar projects likely won’t decrease. But, for the present, developers must rely upon government incentives to entice investor and lender interest, especially as the country emerges from a recession and financing markets remain tight.</p>
</div></div></div><div class="field-collection-container clearfix"><div class="field field-name-field-sidebar field-type-field-collection field-label-above"><div class="field-label">Sidebar:&nbsp;</div><div class="field-items"><div class="field-item even"><div class="field-collection-view clearfix view-mode-full field-collection-view-final"><div class="entity entity-field-collection-item field-collection-item-field-sidebar clearfix">
<div class="content">
<div class="field field-name-field-sidebar-title field-type-text field-label-above"><div class="field-label">Sidebar Title:&nbsp;</div><div class="field-items"><div class="field-item even">&lt;b&gt;Solar Power and State Mandates &lt;/b&gt;</div></div></div><div class="field field-name-field-sidebar-body field-type-text-long field-label-above"><div class="field-label">Sidebar Body:&nbsp;</div><div class="field-items"><div class="field-item even"><!--smart_paging_autop_filter--><!--smart_paging_filter--><p>At the utility-scale level, California represents the dominant solar-energy market, followed by Arizona, Colorado and New Jersey.</p><p>Thanks to state-driven energy independence initiatives, some states with large solar projects are somewhat counterintuitive. For example, 10 northeastern and Mid-Atlantic states formed an alliance with the goal to cut carbon dioxide emissions from power production by 10 percent by 2018. Typically one wouldn’t view northeastern states as solar leaders, but New Jersey in fact has the fastest growing utility-scale solar market in the U.S. In the South, where one would expect to see significant solar projects and a more developed market for solar energy, only Florida, North Carolina and Texas have meaningful projects underway.</p><p>In many states the demand and market for solar energy is minimal to nonexistent, largely due to climate issues, underdeveloped grid interconnection and infrastructure, low consumer demand and the lack of solar-specific RPS. Twenty-nine states plus the District of Columbia have adopted mandatory RPS policies<sup>1</sup> and seven additional states have adopted non-binding goals.<sup><span style="vertical-align: super; ">2</span></sup></p><p>Approximately a dozen states have RPS policies with solar carve-outs or multipliers. Federal, state and local solar-specific RFPs are also becoming more common as stimulus funding is being used and government-driven energy independence initiatives are being expanded. Utilities are beginning to realize they can’t meet RPS or be competitive for certain RFPs by relying solely on commercial and residential-scale projects alone. As a result, utility-scale projects are arguably the fastest growing segment in the solar market.–KB</p><p> </p><h4><span>Endnotes: </span></h4><p><span>1. Arizona, California, Colorado, Connecticut, Delaware, Hawaii, Illinois, Iowa, Kansas, Maine, Maryland, Massachusetts, Michigan, Minnesota, Missouri, Montana, Nevada, New Hampshire, New Jersey, New Mexico, New York, North Carolina, Ohio, Oregon, Pennsylvania, Rhode Island, Texas, Washington, Washington, D.C., Wisconsin.</span></p><p><span>2. North Dakota, Oklahoma, South Dakota, Utah, Vermont, Virginia, West Virginia.</span></p></div></div></div> </div>
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</div></div></div></div></div><div class="field field-name-field-article-category field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Category (Actual): </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/article-categories/renewables-solar-11505">Solar</a></li><li class="taxonomy-term-reference-1"><a href="/article-categories/strategy-planning">Strategy &amp; Planning</a></li><li class="taxonomy-term-reference-2"><a href="/article-categories/states">The States</a></li></ul></div><div class="field field-name-field-members-only field-type-list-boolean field-label-above"><div class="field-label">Viewable to All?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-article-featured field-type-list-boolean field-label-above"><div class="field-label">Is Featured?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-department field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Department: </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/department/business-money">Business &amp; Money</a></li></ul></div><div class="field field-name-field-image-picture field-type-image field-label-above"><div class="field-label">Image Picture:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="https://www.fortnightly.com/sites/default/files/article_images/1103/images/1103-BIZ.jpg" width="1214" height="1500" alt="" /></div></div></div><div class="field field-name-field-fortnightly-40 field-type-list-boolean field-label-above"><div class="field-label">Is Fortnightly 40?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-law-lawyers field-type-list-boolean field-label-above"><div class="field-label">Is Law &amp; Lawyers:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-tags field-type-taxonomy-term-reference field-label-above clearfix">
<div class="field-label">Tags:&nbsp;</div>
<div class="field-items">
<a href="/tags/ccgt">CCGT</a><span class="pur_comma">, </span><a href="/tags/china">China</a><span class="pur_comma">, </span><a href="/tags/commercial-scale">Commercial-scale</a><span class="pur_comma">, </span><a href="/tags/csp">CSP</a><span class="pur_comma">, </span><a href="/tags/debt-markets">Debt markets</a><span class="pur_comma">, </span><a href="/tags/department-energy">Department of Energy</a><span class="pur_comma">, </span><a href="/tags/doe">DOE</a><span class="pur_comma">, </span><a href="/tags/feed-tariffs">Feed-in tariffs</a><span class="pur_comma">, </span><a href="/tags/finance">Finance</a><span class="pur_comma">, </span><a href="/tags/investment-tax-credit">Investment tax credit</a><span class="pur_comma">, </span><a href="/tags/investment-tax-credits">Investment tax credits</a><span class="pur_comma">, </span><a href="/tags/irr">IRR</a><span class="pur_comma">, </span><a href="/tags/large-scale-projects">Large-scale projects</a><span class="pur_comma">, </span><a href="/tags/leed-certification">LEED certification</a><span class="pur_comma">, </span><a href="/tags/mandates">Mandates</a><span class="pur_comma">, </span><a href="/tags/permitting">Permitting</a><span class="pur_comma">, </span><a href="/tags/power-purchase-agreement">Power purchase agreement</a><span class="pur_comma">, </span><a href="/tags/power-purchase-agreements">Power purchase agreements</a><span class="pur_comma">, </span><a href="/tags/power-purchase-agreements-ppa">Power purchase agreements (PPA)</a><span class="pur_comma">, </span><a href="/tags/ppa">PPA</a><span class="pur_comma">, </span><a href="/tags/pv">PV</a><span class="pur_comma">, </span><a href="/tags/rps">RPS</a><span class="pur_comma">, </span><a href="/tags/solar">Solar</a><span class="pur_comma">, </span><a href="/tags/solar-energy-industries-association">Solar Energy Industries Association</a><span class="pur_comma">, </span><a href="/tags/solar-panels">solar panels</a><span class="pur_comma">, </span><a href="/tags/solar-power">Solar power</a><span class="pur_comma">, </span><a href="/tags/tax-credits">Tax credits</a><span class="pur_comma">, </span><a href="/tags/tax-exempt-bonds">Tax-exempt bonds</a><span class="pur_comma">, </span><a href="/tags/vertical-integration">Vertical integration</a> </div>
</div>
Tue, 01 Mar 2011 05:00:00 +0000puradmin14117 at https://www.fortnightly.comUtilities and BPL: Betting Against the Oddshttps://www.fortnightly.com/fortnightly/2005/04/utilities-and-bpl-betting-against-odds
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Why broadband over power line (BPL) can't stand alone as a high-speed Internet offering.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>William P. Zarakas and Kenneth J. Martinian</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><div><strong>William P. Zarakas</strong> is a principal with The Brattle Group, an economic consulting firm. He also heads Brattle’s telecommunications practice. <strong>Kenneth J. Martinian</strong> is a senior associate in The Brattle Group’s telecommunications practice, where he specializes in modeling broadband markets.</div>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - April 2005</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="https://www.fortnightly.com/sites/default/files/0504-FEA3-fig1.jpg" width="1476" height="1424" alt="Figure 1 - BPL-Per-Customer Economics" title="Figure 1 - BPL-Per-Customer Economics" /></div><div class="field-item odd"><img src="https://www.fortnightly.com/sites/default/files/0504-FEA3-fig2.jpg" width="1504" height="944" alt="Figure 2 - BPL-Per-Customer Economics (Nov. 2004)" title="Figure 2 - BPL-Per-Customer Economics (Nov. 2004)" /></div><div class="field-item even"><img src="https://www.fortnightly.com/sites/default/files/0504-FEA3-fig3.jpg" width="1392" height="461" alt="Figure 3 - Range of BPL Market Values (Billions)" title="Figure 3 - Range of BPL Market Values (Billions)" /></div><div class="field-item odd"><img src="https://www.fortnightly.com/sites/default/files/0504-FEA3-fig4.jpg" width="1380" height="527" alt="Figure 4 - Illustrative Allocation of BPL Value by Residential Market Share" title="Figure 4 - Illustrative Allocation of BPL Value by Residential Market Share" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>You could almost feel former FCC Chairman Michael Powell's enthusiasm for broadband over power line (BPL) technology when he called it "the most important third way" to provide broadband to markets across the United States.</p>
<p>Despite advances by DSL and cable modems, the United States ranks 10th in penetration of broadband and data rate of the broadband services offered (among Organization for Economic Cooperations and Development countries)-a fall from the number three spot in 2000.</p>
<p>Although investment in broadband facilities to serve enterprise and large business customers is well under way, the FCC recognizes that improving the U.S. position requires addressing the mass market-and it is here that BPL holds promise. But is BPL financially attractive enough to the nation's electric utilities to warrant investment and management attention?</p>
<h4><font color="red">The Story of Broadband Demand</font></h4>
<p>During the 1990s, entrepreneurs built excruciatingly detailed cost models of telecom networks, but the projections for demand, pricing, and market size were remarkably simplistic. The resulting impact on investors was widespread and devastating. Today's investors are much smarter, and they pay closer attention to demand.</p>
<p>BPL is best suited for mass-market applications, and BPL initiatives right now are targeted at this segment-particularly residential customers, the majority of whom already have two broadband options, DSL and cable modem-while other options are being piloted or deployed.<sup>1 </sup></p>
<p>Broadband market analysts typically measure the size of the residential segment in terms of households. Analysts expect that by year end 2005, overall Internet penetration will reach around 64 percent of the 115 million households in the United States. Assuming current levels of price and income elasticities, 62 percent of households using the Internet will subscribe to broadband service, if available in their area.<sup>2</sup> By the end of 2005, approximately 46 million U.S. households will subscribe to broadband service (or would if it were available), and approximately 89 percent (or about 102 million U.S. households) will have access to DSL or cable modem. The remaining 11 percent (or approximately 13 million households) are too difficult or costly to serve via cable modem or DSL services.</p>
<p>This snapshot of the general landscape in which BPL will compete confirms a common phenomenon faced by developers of telecom infrastructure. Geographic markets that are viewed as highly attractive because of high density levels have already attracted rivals, while areas that are less attractive because of low density levels are wide open to new entrants. New entrants into markets where incumbents already are operating typically face an uphill battle. In these markets, BPL has to compete with DSL and cable modem in terms of price, service quality,<sup>3</sup> and brand. For the market currently unaddressed by DSL and cable modem, BPL has an advantage, but the lack of density in these markets makes achieving scale and favorable economics a challenge.</p>
<h4><font color="red">The Broadband Financial Model: The Devil in the Data </font></h4>
<p>The economics of broadband markets are determined by several key factors, notably: prices and average revenue per user (ARPU), capital expenditures (cap-ex),<sup>4</sup> operating costs (op-ex), customer acquisition costs, and churn. The values for each of these variables depend on the specific geographic areas under study, with rural areas tending to have higher cap-ex and op-ex per line but lower levels of competition (and thus lower customer acquisition costs and lower levels of churn). Urban and suburban areas tend to have lower cap-ex and op-ex per line but higher levels of competition.</p>
<p>We developed a simple model of a retail BPL provider.<sup>5</sup> We use a per-customer discounted-cash-flow model to calculate value per customer, measured as internal rate of return (IRR) per customer.<sup>6</sup> We developed scenarios of different combinations of ARPU, monthly churn and incremental capital expenditure per line to reflect different geographic and market conditions. Higher levels of IRR are achieved under conditions in which cap-ex is low and ARPU is high but, as we discussed above, this combination of factors occurs infrequently.</p>
<p>The contours in Figure 1 show the per-customer IRR for representative combinations of ARPU, monthly churn, and cap-ex, and demonstrate the sensitivity of IRR to changes in these variables. We highlight three specific scenarios that illustrate markets in which utilities may operate.<sup>7</sup></p>
<ul>
<li>Area A represents a rural market with a low level of broadband competition. This market is characterized by ARPU between $38 and $42 per month (which is on the high side of the national average for DSL), cap-ex of $700 to $1,000 per line, and a churn rate of 1.3 percent to 1.5 percent. The resulting IRR is between 0 and 10 percent. Applying a 10 percent cost of capital yields a negative net present value (NPV) on a per-customer basis.</li>
</ul>
<ul>
<li>Area C illustrates an urban or suburban market with a high level of broadband competition. This market is characterized by ARPU between $26 and $32 per month, cap-ex per line between $500 and $700, and a churn rate of 1.9 percent to 2.1 percent. The resulting IRR is between -10 percent and 0. Applying a cost of capital of 10 percent yields a negative NPV on a per-customer basis.</li>
</ul>
<ul>
<li>Area B is an example of a niche market. This may be a densely clustered community in an otherwise rural area, with a low level of broadband competition. This market is characterized by ARPU between $38 and $44 per month, cap-ex per line between $300 and $500, and a churn rate of 1.2 percent to 1.5 percent. The resulting IRR is between 10 percent and 20 percent. Applying a cost of capital of 10 percent yields an NPV from $300 to $500 on a per-customer basis.</li>
</ul>
<p>These low and sometimes negative IRR and NPVs call into question whether entry into broadband markets is financially attractive enough to generate sufficient enthusiasm for utilities to continue to pursue this opportunity. To this, we also add the question of whether or not the BPL opportunity is big enough to make a difference to utilities.</p>
<h4><font color="red">By Enterprise Value: How Attractive Is BPL?</font></h4>
<p>To answer the question of financial attractiveness, we compare the enterprise value per customer of a hypothetical BPL player with a panel of telecommunications and cable television companies.<sup>8</sup></p>
<p>We include the BPL player operating in Area B, the scenario which had the highest IRR per customer, for this comparison. (Below we discuss the BPL players operating in Areas A and C.) As shown in Figure 2, the BPL provider depicted here has an estimated enterprise value per line that is well below that of the panel of telecommunications and cable television companies. Cox and Comcast have the highest enterprise value per customer. These cable television companies offer cable television, high-speed Internet access over cable modem, and digital cable telephony over their hybrid coaxial cable and fiber-optic networks. The major telephone companies (SBC, Verizon, BellSouth, and Qwest) have lower enterprise values per customer than Cox and Comcast. They have been losing access lines but gaining DSL subscribers, and they plan on offering video services by improving capacity on their networks (through the deployment of fiber optics). Telephone companies CenturyTel, Citizens, and AllTel operate primarily in rural areas and face lower levels of competition than the regional Bells.</p>
<p>Three primary factors contribute to the comparatively low enterprise values for BPL. First and foremost is the difference in ARPU realized by the BPL provider compared with others in the panel. The other companies provide multiple services to customers over a common infrastructure. Cable television companies provide a "triple play" of voice, data, and video, and telephone companies hope to soon. The monthly bill for a residential customer subscribing to the entire triple play might be as high as $120 to $150.<sup>9</sup> Since all customers will not take the triple play, ARPU will not rise to this level. It may increase to about $70 per month, though. If the ARPU for BPL could rise to this level, enterprise value would increase by up to $1,000 per customer.</p>
<p>Second, churn, or the degree to which customers switch to other providers, has a pronounced impact on value. Incumbents typically enjoy lower levels of churn than newer entrants. We assumed a relatively low churn level of 1.5 percent for the BPL provider shown here. If the BPL provider could lower this assumed churn level as a result of brand recognition, consumer recognition of high-quality service, or bundling options, churn could be driven down to levels closer to the incumbents. This could boost value another $300 or $400 per customer.</p>
<p>Third, a portion of the difference in value may be attributed to the capital expenditures that are included in the calculation of enterprise value. The telephone companies and cable companies in our panel have deployed their networks over decades. Much of their investment already has been recouped. Utilities currently have a network in place but will have to incur cap-ex to realize BPL functionality. If the BPL provider could recoup its investment, value could increase by about $400 per customer. However, there is little that the utility can do to change this circumstance other than strive to keep cap-ex per line as low as possible or to receive a subsidy.</p>
<p>Combining the three factors—higher ARPU, lower churn, and lower cap-ex—could increase BPL enterprise value by about $1,800. This would place this BPL player's enterprise value in the mainstream of our panel. The economics of the BPL players operating in Areas A and C could also improve with these factors, although they would not compare as favorably to the panel as does the BPL player in Area B. The BPL market for the U.S. market as a whole likely would be a blend of these three areas. This means that ARPU and enterprise value per customer likely would be lower industry-wide than for the player operating in Area B.</p>
<h4><font color="red">Management: What to Consider?</font></h4>
<p>Assuming that BPL is sufficiently financially attractive to raise the interest of electric utilities, is it material enough an opportunity (, is it big enough) to merit management attention? A definitive estimate of the size of BPL opportunity (, its industry-wide value) is difficult to gauge fully at this time because the key driver—cap-ex per customer—is still in flux. We estimate values for BPL industry-wide based on combinations of market share and cap-ex per line at various levels of service offerings and ARPU.</p>
<p>As shown in Figure 3, the potential market value is greatest with high market shares and high levels of ARPU.</p>
<p>If we take the middle of the ranges shown in this figure, industry-wide value for BPL is around $2.9 billion. This value depends on a set of modestly favorable assumptions: moderate to low cap-ex (about $400 per customer), ARPU that is higher than that for standalone, high-speed Internet access (about $45 per month),<sup>10</sup> and a strong market share (about 20 percent).<sup>11</sup> To attain a 20 percent market share nationwide, BPL would have to capture at least 10 percent of the market where broadband is already available and nearly all of the addressable market in areas where broadband currently is not available.</p>
<p>This value of $2.9 billion is relatively small when compared with the market capitalization of the electric utility industry. In Figure 4, we show the market capitalizations for five large electric utilities in the United States.</p>
<p>If we assume that each of these utilities entered the BPL business, and we further assumed a uniform allocation of total BPL industry value (, $2.9 billion) based on number of residential customers for these utilities, we see that the contribution of BPL to overall enterprise value would be between 0.2 percent and 1 percent for each utility.<sup>12</sup> If we make our assumptions more optimistic—higher market share, higher ARPU, and lower cap-ex per customer—total industry value may increase three-fold, to about $10.4 billion. Still, using the simplifying assumptions made earlier, the impact on the utilities shown above would be less than 4 percent.</p>
<p>In our view, all other things being equal, the size of the opportunity would have to be greater than this level to merit significant management interest in BPL commercialization for many of the nation's electric utilities. Several utilities have expressed their concerns about straying out of their core areas of business competency, especially in light of failed rounds of utility diversification in the past and the wave of telecom bankruptcies following the bursting of the telecom bubble. The economics of BPL and the overall contribution to enterprise value may change considerably, however, if BPL is viewed as an enabling technology for utility operations in addition to its commercial potential.</p>
<p>Each year, the U.S. electric utility industry spends about $3.5 billion on telecommunications equipment and services for its own internal uses.<sup>13</sup> Further, many utilities have represented the need to drive enhanced bandwidth deeper into their systems to enable advances in their own internal utility operation. As utilities push intelligence further into their systems to realize "smart grid" functionality,<sup>14</sup> greater communication capabilities are required closer to the end-use customer. Allocating a portion of the cost of deploying BPL to the utility improves the economics of the commercial portion of BPL.<sup>15</sup> The utility still will have to make the full investment in BPL, but it will realize rewards in terms of improvements in its core electric utility operations, as well as returns from its BPL business. Here, the utility may view BPL's commercial opportunity as a secondary benefit, as opposed to a primary driver.</p>
<h4><font color="red">The Obstacles to Broadband</font></h4>
<p>It goes without saying that BPL's entry into the commercial broadband market, even under the most favorable bundling circumstances, will be challenging. The battle for broadband customers already is highly competitive. Given the difficult time telephone companies have had capturing market share for high-speed Internet access from cable companies, BPL providers likely will face similar, if not greater, challenges. If the ramp-up in BPL market share is too slow, the cost per customer will be too high (due to lack of scale) to yield a strong return on investment. Conversely, if customers are quite willing to switch to a BPL provider (a necessary condition for a quick ramp-up), they also may be quite willing to switch away just as easily. The resulting high churn in such a scenario would hurt per-customer economics. This situation is exacerbated by the dynamic nature of telecommunications and media markets in general. New technologies and applications have had highly disruptive effects upon even the most well thought-out business plans.</p>
<p>In our view, multiple product offerings (and of course higher ARPU) are required to make BPL an attractive commercial prospect for investor-owned utilities. As BPL's rivals lower the price for the bundle of triple-play services, ARPU will decline and margins on BPL products will be squeezed. For the BPL player, Voice over Internet Protocol (VoIP) over BPL is at least a partial solution to this problem. The addition of VoIP will serve to increase ARPU levels and increase IRR per customer.<sup>16</sup> Failure to expand BPL service offerings from standalone provisions of high-speed Internet access, however, significantly lessens the attractiveness of BPL to both utilities and investors.</p>
<p>The economics of BPL also may be improved through partnering and facility sharing. Partnering with, for example, an Internet service provider may prove attractive because such a relationship can reduce costs through greater scale. The partner also may provide needed technical or marketing expertise. For utilities that view the commercial opportunities of BPL as secondary to enabling improvements to core electric utility operations, partnering also may reduce management distraction.</p>
<p>Without the bundling of multiple services over BPL, high-speed Internet access over BPL as a standalone product may be commercially viable only in certain applications-perhaps from municipal and cooperative utilities, and from some small to mid-sized utilities. Many municipal and cooperative electric utilities view their mission broadly, in terms of providing needed services to their customers, so estimates of low per-customer IRRs may not present a huge hurdle for these utilities, as long as the IRRs are modestly positive and broadband service is needed by customers. This also may facilitate the FCC's vision to provide broadband service in rural areas.</p>
<p>Most investor-owned utilities may not view their charter as broadly, however, so they may be able to justify commercialization of BPL as a standalone product only in limited, niche applications.</p>
<h4><i class="endnote">Endnotes:</i></h4>
<ol>
<li>Other broadband technologies that are currently being piloted include fiber-to-the-home (FTTH), loop extended DSL, WiFi and WiMax, 3G wireless, and broadband over satellite.</li>
<li>We assume that households in areas currently without broadband will switch from dial-up to a new broadband service at the same rate as in areas where broadband is currently available.</li>
<li>This includes data rate, reliability, and customer care.</li>
<li>Cap-ex is a major factor affecting the success of the BPL business model. Cap-ex is a function of the prices for BPL equipment, network topology, household density, and market share. Manufacturers have released few prices to date. Overall, cap-ex per customer varies greatly. In our analysis, we use a range of cap-ex values.</li>
<li>This simple model is based on comprehensive and dynamic models that we regularly develop to analyze broadband markets.</li>
<li>We show value as an internal rate of return (IRR) per customer over the "customer lifetime" (, the average period of time that the customer generates revenue before disconnecting or churning to a competitor).</li>
<li>Clearly, a specific BPL deployment may not fit neatly into any of these three scenarios. They are intended as illustrative only.</li>
<li>We selected a panel of 15 wireline communications companies (i.e., we excluded the wireless communications portions). Enterprise value is the value of business operations without debt or cash. We estimated enterprise value per customer by subtracting cash plus debt from market capitalization and then dividing this value by the number of customers. Enterprise value per customer may be compared to NPV per customer calculated with a discounted cash flow (DCF) model. We used DCF to calculate enterprise value for our illustrative BPL provider.</li>
<li>For example, this may be composed of $40 for local voice service, $20 for long-distance service, $40 for broadband Internet access, and another $40 to $60 for video or cable television. A discount for subscribing to a bundle of services is then applied.</li>
<li>Pricing for BPL in most current trials is about $30, the same price as DSL in many markets. To attain a $45 ARPU, a BPL provider would require at least some other revenue stream: perhaps VoIP or Internet value-added services (, security, home management, home area network maintenance, e-mail, Web hosting, etc.).</li>
<li>This analysis holds churn constant at a relatively low value of 1.5 percent per month.</li>
<li>Of course, this is a simplifying assumption. Actual value for BPL is a function of a variety of factors, many of which we discussed earlier. The portion of the BPL market realized by the utilities in this panel could be more or less than that represented here.</li>
<li>According to the United Telecom Council. Uses include coordinating power dispatch and transmission, among other functions.</li>
<li>These applications include real-time pricing, automatic shut on/off, and monitoring of consumer usage to control and balance loads.</li>
<li>The economics of BPL also will depend on regulatory treatment of cost allocations.</li>
<li>It also is likely to reduce churn given the known effect of product bundling on customer "stickiness."</li>
</ol>
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Fri, 01 Apr 2005 05:00:00 +0000puradmin10864 at https://www.fortnightly.comTechnology Corridorhttps://www.fortnightly.com/fortnightly/2003/08/technology-corridor
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>How the wind farm capacity factor and a tax subsidy can beef up a utility&#039;s bottom line.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Gary C. Young</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - August 2003</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><blockquote><p></p>
<h3>How the wind farm capacity factor and a tax subsidy can beef up a utility's bottom line.</h3>
<p>Many interested by a profit motive or an environmental motive wax eloquently about the economy of wind farms to generate electricity, since wind energy is an environmentally friendly source of energy or "green power." Thus, the interest in wind farms attracts the attention of citizens, environmental groups, politicians, and commercial companies.</p>
<p>With this diverse interest, a sense of direction is needed to bring a reality check on the economics of wind farms. Consider the following example for a large-scale wind farm.</p>
<p>MidAmerican Energy Inc. plans to build the world's largest wind energy generation project in Iowa.<sup>1</sup> The reportedly $323 million project will consist of 180 to 200 wind turbines and have a capacity of 310 MW. An additional capital cost of $15 million for interconnecting and development adds up to a total estimated capital cost of $338 million for the economic evaluation. Landowners will be paid $4,000 per turbine annually for easements.</p>
<p>With this data as a basis, consider the economics of this project in two case studies (see next page).</p>
<p>Case 1 uses a capacity factor of 35 percent to approximate a break-even cost of 3.4 cents kWh for wind-generated electric power from a large wind farm. If a more detailed economic analysis is done using the Modified Accelerated Cost Recovery System (MACRS), the break-even price for wind energy turns out to be 3.4 cents/kWh-illustrating that the approximation method can be useful. For another site where the capacity factor is lower and the site-specific case has a capacity factor of 20 percent,<sup>2</sup> the break-even cost increases and the value becomes about 5.9 cents/kWh using the approximation method.</p>
<p>The economic analysis<sup>3</sup> of Case 2 yields an Internal Rate of Return (IRR) after taxes of 4.26 percent when the selling price of wind farm-generated energy is 3.4 cents/kWh, with no federal tax credit. Case 3 includes a federal tax credit of 1.8 cents/kWh of wind farm energy generated for customers, with all other factors the same as Case 2. The annual federal tax credit becomes $17.1 million (950,463,000 kWh/year x $0.018/kWh).</p>
<p>This subsidy in effect increases the IRR (after taxes) to 27.1 percent. If, for this same case, the debt was decreased to 60 percent at 7 percent interest and with a 40 percent equity, the IRR (after taxes) would be reduced to 13.8 percent considering the federal tax subsidy, but with the operation/maintenance cost increased from $3.23 million to $5 million per year.</p>
<p>These analyses illustrate the economics of wind farming, the importance of the wind farm capacity factor, and that a tax subsidy can generate much cash to the bottom line of a utility in a specific and properly chosen wind-farm site.</p>
<p>Another factor to consider is the matter of "green credits." Customers, if they wish, can be charged extra by the utility for purchasing wind energy. This additional revenue can make a project more profitable.</p>
<p>A state wind energy tax credit of 1.0 cent/kWh, such as recently contemplated for the state of Iowa, was not considered in this study. This additional state subsidy would increase the rate of return substantially.</p>
<p>Any economic analysis should be site/case-specific. The economics presented in this article are presented only as information to the public.</p>
<p><b></b></p>
<ol>
<li>Boshart, Rod, "Wind Plant to Generate Revenue," , March 26, 2003.</li>
<li>Private communication, Dave DeWitte, , April 22, 2003.</li>
<li>Phillips, C., "Private Communications, Financial and Economic Review," Universal Electric Power Inc., May 2003.</li>
</ol>
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Fri, 01 Aug 2003 04:00:00 +0000puradmin11282 at https://www.fortnightly.comNuclear and Coal: Rebirth on the Horizon?https://www.fortnightly.com/fortnightly/2001/11/nuclear-and-coal-rebirth-horizon
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>An analysis of the business opportunities behind coal and nuclear plant expansion.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Mark Hand</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - November 1 2001</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><blockquote><p></p>
</p>
<p> </p>
<h3>An analysis of the business opportunities behind coal and nuclear plant expansion. </h3>
<p> <b>Electric power industry trade publications and the popular media have noted</b> a growing interest in the rebirth of both nuclear power and coal-fired generation. These technologies would be a supplement to, or an alternative to, the natural gas fired generation that appears to be the predominant fuel and technology for new power generation facilities in the coming decade. </p>
<p>Nuclear power enthusiasts express the notion that this country's need for several hundred thousand megawatts of new generating capacity over the next 10 to 20 years, the interests of fuel diversity, clean air issues, and energy security should be enough to drive this rebirth. Coal enthusiasts stress that new coal-fired generators can be much cleaner than existing units, and clean enough to meet anticipated stringent environmental requirements. We have not seen a strong advocacy on the basis of competitive financial opportunity, although the growing number of new coal-fired project announcements suggests that some developers see such opportunity. </p>
<p>With regard to nuclear, there appears to be a divergence of views, with advocates sensing that energy policy issues will drive rebirth, and the financial community sensing that a realistic promise of sound economics and profitability in the competitive generation environment is an essential prerequisite to any rebirth. </p>
<p>According to Douglas Kimmelman, a chief energy analyst with Goldman Sachs, "It really comes down to the fully loaded capital cost. Unfortunately, investors won't make decisions based on national energy policy."<sup>1</sup> We agree with the investment community, which lead us to undertake this brief study of the prospective economic and financial drivers of new nuclear and coal fired generation. </p>
<h3>Regional Diversity: Are Nuclear and Coal the Answer Everywhere? </h3>
<p>Approximately 45,000 megawatts of new coal-fired generation projects have been "announced"; some appear to be under serious development.<sup>2</sup> About 12,000 megawatts are proposed for the Western Systems Coordinating Council (WSCC). In the East, the NERC regions SPP, ECAR, MAIN, and SERC appear to be most active. While several leading nuclear plant operators have expressed interest in developing new nuclear plants, we know of no firm development plans at this time. Natural gas fired simple cycle combustion turbine and combined cycle units very heavily dominate the new generation outlook in all markets. </p>
<p>Our study focuses on several key questions (see sidebar, ). It considers new coal plants brought into service in 2006, and new nuclear plants brought into service in either 2006 or 2011, in some or all of nine selected market areas within the Eastern Interconnection. </p>
<p>The key figure of merit is the all-inclusive nuclear or coal plant initial capital cost, expressed in year 2001 dollars per kilowatt, that yields an internal rate of return (IRR) value that is comparable to the value projected for contemporary (in time and location) natural gas-fired combined cycle units. The latter are selected as the reference because of their energy producer role, even though in some markets, notably ECAR, simple cycle combustion turbine peaking units may be financially preferable to combined cycle units in certain time frames. These "parity capital costs" for coal and nuclear may be viewed as benchmarks, subject to the conditions and limitations of this study, for judgments regarding the economic and financial competitiveness of new projects. </p>
<p>A high "parity capital cost" indicates strong market receptivity to new coal or nuclear, relatively high competitiveness with combined cycle, and relatively high financial margins. In other words, new projects having relatively high capital costs can be economically competitive and financially attractive. Comparisons with anticipated new plant costs can provide insights as to whether projects in general or specific projects are likely to be financially attractive, but a cautionary note is in order when comparing specific projects to the results of this study. Individual developers and projects may have very different views of the future and/or financial parameters than those that underlie this study. </p>
<p>Results are presented for three scenarios (see Table 1, ). Scenario 1 assumes substantial installed capacity or ICAP markets everywhere, and substantial revenues therefrom for all generators. This scenario utilizes the reference gas price trajectory. Scenario 2 is based on a market structure in which there are only minimal ICAP revenues, and generators must rely on the energy market for profitability to a much greater degree. The reference gas price trajectory is used here as well. Scenario 3 is based on the Scenario 1 market structure, but assumes a 20 percent higher gas price trajectory. Only one scenario of environmental regulation requirements is considered; alternatives are beyond the scope of the present study. Sensitivity cases were examined for variations in financing costs and for nuclear plant fixed operation and maintenance costs. The following observations emerge from these scenario results. </p>
<p>Clearly, both coal and nuclear benefit from an increase in gas prices. The 20-percent increase in Scenario 3 relative to Scenario 1 yields a parity capital cost increase of about $210 per kilowatt for both types of base load units. </p>
<p>Market structure is somewhat important in this study, with both coal and nuclear benefiting from a structure that incorporates an explicit ICAP market. The advantage in parity capital costs is about $100 per kilowatt for both. However, we have considered only a very limited subset of the many possible bidding strategies that market participants could adopt. Results may be different for alternative bidding strategies. </p>
<p>For coal units, the most favorable and least favorable markets are consistent in the three scenarios. This is substantially true for nuclear as well. </p>
<p>PJM appears to be among the best markets for both coal and nuclear. </p>
<p>MAIN appears to be among the least favorable markets for both coal and nuclear, probably because of the large existing population of base load generators. While it is important for every new project to minimize fuel costs, this may be particularly important for proposed coal plants in MAIN. This study assumed new projects would use a typical local coal with an escalated typical recent historical price. Very recent EIA data indicate that coal prices in Illinois in particular are being reduced, perhaps more than is reflected here. Also, it may be advantageous for a new MAIN project to utilize Powder River Basin coal. </p>
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<h2><font color="#FFFFFF">Finding the Answers: <font size="4"><br />The Key Questions for Nuclear and Coal Development</font></font> </h2>
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<p>How strong are the financial and economic drivers for expanded development of coal-fired generation and the reintroduction of nuclear? Under what circumstances are new nuclear and coal plants likely to be financially competitive with new gas-fired combined cycle plants? From the developer and financial community perspectives, taking relative risks into account, under what circumstances would there be a preference for nuclear or coal rather than gas? The key questions include: </p>
<p>1. What envelope of initial capital costs and ongoing fixed operation and maintenance costs must new nuclear plants and new coal plants stay within in order to be financially competitive with new combined cycle plants? Nuclear costs should include allowances for a decommissioning sinking fund and ongoing nuclear waste disposal costs. Coal plant costs should include meeting environmental requirements. </p>
<p>2. How does this cost envelope shift under alternative scenarios of natural gas price trajectories? </p>
<p>3. How does wholesale power market structure affect competitiveness? </p>
<p>4. Are some generation markets more attractive than others for new nuclear or coal plants in the 2006 through 2011 time frame? </p>
<p>5. How will financial risk premiums that investors are likely to demand for new nuclear and coal plants impact on competitiveness? </p>
<p>6. New coal-fired generation is experiencing a stronger rebirth at this time than nuclear plants. Since gas may not be the only competitor, how competitive are new nuclear plants in a scenario of widespread new coal plants? </p>
<p>7. What is the impact of alternative environmental regulation scenarios for coal plants? Under what scenarios would nuclear be clearly preferable economically and financially? </p>
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</table>
<p>For nuclear, increasing the fixed O&amp;M costs (including capital additions) from $65 per kilowatt year to $100 per kilowatt year reduces the parity capital cost by about $260 per kilowatt. This illustrates both the importance of controlling O&amp;M costs and the financial risk of future O&amp;M cost flyups due to new regulatory requirements and/or equipment replacement needs. </p>
<p>The base case financial parameters used in this study are summarized in Figure 1. The base cases assume that these parameters would be the same for gas-fired combined cycle, coal, and nuclear. </p>
<p>It seems reasonable to expect higher financing costs for coal because of financial risks associated with future environmental regulations. Higher financing costs in terms of a 10-percentage point increase in equity (vs. debt) requirement, and half a percentage point increase in debt cost reduces the parity capital costs by $80-100 per kilowatt, depending on the scenario. It seems reasonable to expect even higher financing costs for nuclear because of financial risks associated with new NRC requirements that may be triggered by events at the subject plant or even at another plant having a different owner, by equipment performance and replacement needs, and with public acceptance shifts. Higher financing costs in terms of a 20-percentage point increase in equity (vs. debt) requirements and a full percentage point increase in debt cost reduce parity capital costs by about $165-212 per kilowatt, depending on the scenario. </p>
<h3>Making the Numbers Work: What are the Capital Costs? </h3>
<p>The Energy Information Administration's "advanced nuclear case" shows a capital cost of about $1735 per kilowatt in 2001 dollars for plants in the 2005 time frame, and about $1560 per kilowatt for plants in the 2010 time frame<sup>3</sup> These figures are quite a bit higher than our parity capital costs. In a recent interview with Entergy executives on nuclear issues, they said it would take a nuclear design whose cost is less than $1000 per kilowatt to stimulate high interest on the part of Entergy. In addition they indicated that there are several designs on the drawing boards that meet this criterion.<sup>4</sup> We hope so, since our parity capital costs suggest that this is the cost range needed for financial competitiveness. </p>
<p>Cost estimates for coal-fired plants of $1082 per kilowatt to $1190 per kilowatt would meet cost requirements if they were constructed with a modular approach.<sup>5</sup> This represents a 10 percent to 15 percent cost reduction relative to stick built plants (IBID). Accordingly, a 2001 capital cost of about $1150 per kilowatt for conventional pulverized coal plants with in-service dates in the 2005 time frame (Footnote 3, Table 43, IBID). These figures appear to be almost competitive with our parity capital costs in the most favorable markets, assuming our reference gas price projection. More comfort is obtained with the 20 percent higher gas prices. </p>
<p>This study assumed a relatively favorable scenario of environmental regulations. Alternative scenarios may significantly reduce the parity capital costs for new coal plants, indicating reduced competitiveness. These scenarios may increase parity capital costs for nuclear. Not surprisingly, new coal and nuclear projects clearly involve bets on gas prices, market selection, and environmental regulations. </p>
<h3>Power Markets: Projections For Nuclear and Coal </h3>
<p>Competitive generation market context is important to understanding the results of any study of this type. This study looks at the entire Eastern Interconnection plus ERCOT. It assumes that a multi-regional competitive power generation marketplace exists throughout this very large geographic area. </p>
<p>For modeling purposes, this area is divided into about 165 individual markets that are linked together in accordance with today's transmission system. </p>
<p>Think of these markets as bubbles on a bubble chart that are joined by lines representing transmission links. Many of these markets are individual merchant plants with no native load obligations. About 50 of these markets are load regions, most having generation within them as well. Major transmission interfaces may limit power flows and transaction opportunities at various locations and times within this broad geographic area. The model includes 30 such interfaces. </p>
<p>It is assumed that regional transmission organizations (RTOs) form everywhere, but in a relatively Balkanized pattern rather than the very few super-regional entities that the FERC is attempting to promote in its orders of July 2001. These RTOs reduce the pancaking of wheeling charges and greatly increase power transaction opportunities relative to the historic marketplace, but probably not to the level envisioned by the FERC plan. </p>
<p>We expect that most new generation, including the gas-fired, coal-fired, and nuclear plants that are the direct subjects of this study, will be merchant plants. Each merchant plant can obtain revenues from the wholesale power marketplace that can be viewed as having three segments: an energy market, an installed capacity or ICAP market, and an ancillary services market. Revenues from the three market segments must be sufficient to cover not only variable operating costs but also fixed operating costs, paying off debt financing, and providing additional revenues so that the equity holders realize target returns on investment or internal rates of return (IRR). It is neither necessary nor realistic that all generators meet financial targets, but most existing generators and new projects needed to maintain generation reserve margins must be able to do so. Revenues from these market segments that are net of the variable costs of securing these revenues are deemed contributions to fixed charges (CTFC). In recent history, the tendency has been to construct gas fired generation because it is the least capital intensive, fastest to permit and construct, and supported by favorable expectations of natural gas availability and cost. Merchant plant developers will be induced to develop more capital intensive technologies, such as coal-fired and nuclear plants, only when the additional contributions to fixed charges from the marketplace are at least sufficient to finance the capital premium while meeting financial targets. </p>
<p>Our market model assumes that reliability will be maintained by enforcing a generation reserve margin obligation in each reserve-sharing pool. In this study, reserve-sharing pools are typically assumed to coincide with a NERC region or sub-region. Reserve margin targets, based on today's targets, range from about 13 to about 20 percent of seasonal peak load, depending on the region. (See sidebar, ) </p>
<p>Raber Consulting maintains an ongoing list of announced new generation projects and tracks their development status. As we sense that a project is likely to come into service, we add it to the database of our energy market model. In the early years of the study, this list of new projects determined whether each reserve-sharing pool has more capacity or less capacity than is called for to meet its reserve obligation. The model adds expansion unit projects to each reserve-sharing pool when the existing level of generation, net of economic retirements, falls to the minimum level required by the reserve margin obligation. In this study, it is assumed that all expansion units will be natural gas fired. A developer perspective on which of these technologies will provide the better IRR drives the mix of simple cycle combustion turbines (CTs) and combined cycle units in each pool. An "equilibrium" mix, which would produce the same IRR for both technologies, is sought. In most market areas, the expansion unit mix is heavily tilted toward combined cycle. ECAR is a notable exception, wanting perhaps 30 percent to 50 percent simple cycle CTs in the mix in order to balance out existing base load generation that will continue operating over many years. </p>
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<h2><font color="#FFFFFF">Building Power Plants in Competitive Markets: <br /><font size="4">An Explanation of Assumptions</font></font></h2>
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<p> The competitive generation market is viewed as having three segments: an energy market, an installed capacity or ICAP market, and an ancillary services market. The energy market is modeled using the Inter-Regional Electric Market Model.<sup>6</sup> This model combines economic dispatch with broad-based inter-market energy transactions to arrive at energy market prices as a function of time, and energy market contributions to fixed charges for each individual generating unit. The ICAP market is modeled with Raber Consulting's spreadsheet model, which is basically an income statement that accepts IREMM results along with accounting, financing, and tax parameters to develop IRR values as a function of time for individual projects. This model is also used to compare new merchant plants of the three technologies. Ancillary services market revenues are expected to be relatively small for the types of generators of interest here, and will depend on market development, generator location, and generator operating and electrical characteristics. A simplified approach was adopted in this study, assuming that the ancillary services market provided a 5-percent bonus to the combined contributions to fixed charges from the energy and ICAP market segments. </p>
<p>Two long-term natural gas price trajectories were considered. The reference projection is based on the reference scenario in EIA's Annual Energy Outlook 2001.<sup>3</sup> Near term prices were updated to EIA's March 2001 Short-Term Outlook. Escalation rates for fossil fuels other than gas were also considered.<sup>3</sup> The high gas price trajectory has gas prices 20 percent above the reference prices starting in 2003. The prices for other fuels are unchanged from the reference in the high gas price scenario. Gas prices are region-dependent. As seen in the results, the financial performance of coal and nuclear plants depends strongly on the spread between their fuel costs and gas costs. </p>
<p>This study assumes that several large companies who already own and operate multiple nuclear plants would be the developers of new plants. These include Dominion Resources, Excelon, Southern Energy, Constellation, Entergy, and Duke. Several of these companies have expressed interest in doing so. New nuclear plants will almost certainly be developed at existing nuclear plant sites. </p>
<p>Economies of volume in manufacturing new nuclear plant components and erecting new units will almost certainly be necessary if competitive cost levels are to be achieved. This study assumed that commitments for eight new plants would be made among the companies listed above, with costs shared in some manner. Four of these plants are assumed to enter service in 2006, which is probably earlier than practicable. The other four are assumed to enter service in 2011. These units are assumed to be conventional pressurized water reactors, for example the standard design AP600, with the characteristics shown in Figure 1, page 44. In this study, fixed O&amp;M costs are assumed to include capital additions. Nuclear fuel costs are assumed to be independent of plant location, and constant in time at about $0.70 per million BTU. This figure is viewed as covering the disposal costs for high-level radioactive wastes whose production is proportional to plant operation; for example, spent nuclear fuel. </p>
<p>The new coal plants to come into service in 2006 are assumed to be pulverized coal units having the characteristics shown in Figure 1, with high efficiency scrubbers for SO<sub>2</sub> removal. </p>
<p>With regard to environmental requirements, this study assumes that extensive NO<sub>x</sub> emissions controls will be required everywhere within the EPA "SIP Call" regions. Most existing generators and all new generators are assumed to have NOx emission controls, most often selective catalytic reduction or SCR for major units. </p>
<p>Outside the "SIP Call" regions, it was assumed that NO<sub>x</sub> emissions controls are not required for either existing or new units. This may well be unrealistic, but tends to maintain competitiveness of new coal-fired merchant plants relative to existing coal-fired units. Unlike nuclear, fuel costs for coal plants vary significantly from region to region. </p>
<p>Each new merchant coal plant was assumed to utilize coals, and see coal prices, that are typical of existing units in that region. In our modeling, each coal-fired generator is assigned its specific coal price and sulfur content based on recent historic data. Obviously, a new unit should seek the best coal prices available because this will directly affect competitiveness. Our study does not assume that these new plants can achieve coal prices below what has been typical for their market areas. This may be important for a new coal unit in MAIN in particular. We assumed it would utilize local coal rather than perhaps cheaper coal from the Powder River Basin, which might enhance its competitiveness. </p>
<p>The fixed operation and maintenance costs for coal units shown in Figure 1 are taken from Table 43,<sup>3</sup> escalated to 2001 dollars. The nuclear plant fixed O&amp;M costs are shown in Figure 1.<sup>7</sup> This $65 per kilowatt-year is reasonably representative of 1997 through 1999 existing plant experience for the best quartile of the existing plant population. The alternative figure used in sensitivity cases, $100 per kilowatt-year, appears reasonably representative of the third quartile experience. Table 433 indicates a fixed O&amp;M cost just under $60 per kilowatt-year in year 2001 dollars. In this study, it is assumed that fixed O&amp;M costs include capital additions. Price projections for SO<sub>2</sub> and NO<sub>x</sub> allowances were taken from the EIA.<sup>8</sup></p>
<p>This study assumes no requirements for carbon emissions, again a potentially unrealistic assumption. Since coal units would be impacted more heavily by CO<sub>2</sub> emission regulations and allowance costs than natural gas-fired units, this assumption tends to enhance the competitiveness of new coal-fired generation. This assumption also tends to reduce the competitiveness of new nuclear plants relative to either gas-fired or coal-fired generators. </p>
<p>The following sensitivity cases were examined in all three scenarios. Sensitivity case results are summarized in Table 1, page 43. </p>
<p>1. New nuclear plant fixed O&amp;M costs increase from $65 per kilowatt-year to $100 per kilowatt-year, in year 2001 dollars.</p>
<p> 2. Financing cost premiums are required. For new coal units, this premium is assumed to be a shift in capitalization from 40 to 50 percent equity, and an increase in debt cost from 8.25 percent to 8.75 percent. For new nuclear units, the shift in capitalization is assumed to be from 40 to 60 percent equity, and the increase in debt cost from 8.25 to 9.25 percent. </p>
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</table>
<p>In essence, this study assumes that new generation will continue to be overwhelmingly gas-fired, with progressive improvements in CT technology. We are examining the financial competitiveness of a small population of new nuclear and coal-fired generators introduced into this "world of gas." In most respects, this should maximize their competitiveness. </p>
<p>Two alternative power market structures were examined for impact on the competitiveness of new coal and nuclear plants. The market model used in Scenarios 1 and 3 assumes that there is an explicit ICAP market in addition to the energy market. In essence, this ICAP market becomes the vehicle for enforcing reliability requirements. It is assumed that energy market competitiveness maintains energy market prices at or near prevailing variable costs. In this study, a minimum profit of $3 per megawatt-hour is added to variable cost to obtain generator bid prices during on-peak hours. This minimum profit before sale was scaled back to $1 per megawatt-hour during mid-peak hours, and to zero during off-peak hours. The ICAP market is then relied upon to provide the revenues necessary for new gas-fired combined cycle and/or simple cycle CTs to meet the specified market average target IRR values when new capacity is needed for reliability. This market model anticipates very low ICAP values in early years when reserve-sharing pools have excess capacity. This value was taken to be $10 per kilowatt-year in today's dollars. </p>
<p>In the market model used in Scenario 2, it is assumed that there is a minimal ICAP market, limiting its revenues to $10 per kilowatt-year in today's dollars. The energy market is now called upon to provide the necessary revenues to allow new gas-fired projects to meet target IRRs when they are needed to meet reliability. This was done by increasing only the on-peak minimum profit before sale on a region-wise basis, but applying it to all generators within each region. In this market model, this energy market bidding strategy was allowed to persist during the early years of excess capacity. This produces much higher IRR values than the market model used in Scenario 1 for merchant plants introduced prior to the need for new capacity to maintain reliability, typically in the 2004 to 2008 time frame. </p>
<p>The study horizon was 2020. For new merchant plants installed in 2006, a target IRR of 16 percent in 2020 was assumed. For new merchant plants installed in 2011, the target IRR was assumed to be 12.5 percent in 2020. Capacity prices and energy market minimum profits were adjusted to have gas-fired merchant plants close to these targets. Capital costs for nuclear and coal units were then adjusted to have their IRR values match those of contemporary gas-fired combined cycle units. </p>
<p>1 , May 30, 2001. Article entitled "Nuclear Power Enthusiasts Grapple With Wall Street Skepticism", page 17. </p>
<p>2 Betsy S. Vaninetti, "The Race for New Coal-fired Generation". Article in , July/August 2001. </p>
<p>3 Energy Information Administration Report: Annual Energy Outlook 2001, DOE/EIA-0383 (2001); December 2000. Also, companion documents presenting assumptions and bases. </p>
<p>4 , July 2001 interview article entitled: "Keuter: On Entergy Nuclear's Acquisitions and Growth." </p>
<p>5 Jerry Gotlieb et al., "Power Plant Design: Taking Full Advantage of Modularization." Article in , June 2001. </p>
<p>6 The Inter-Regional Electric Market Model is developed, maintained, and licensed by IREMM, Inc. See their Web site at <a href="http://www.iremmsupport.com">www.iremmsupport.com</a> or call Mr. Wayne H. Coste at 860-651-1600 for more information. </p>
<p>7 Nuclear Energy Institute status report entitled: "The Outlook for Nuclear Energy in a , January 2001. </p>
<p>8 Energy Information Administration report: "Analysis of Strategies for Reducing Multiple Emissions from Power Plants: Sulfur Dioxide, Nitrogen Oxides, and Carbon Dioxide. SR/OIAF/2000-05. December 2000. </p>
<p><b>Articles found on this page are available to Internet subscribers only. For more information about obtaining a username and password, please call our Customer Service Department at 1-800-368-5001.</b></p>
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Thu, 01 Nov 2001 05:00:00 +0000puradmin10564 at https://www.fortnightly.comFrontlineshttps://www.fortnightly.com/fortnightly/2000/12/frontlines
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Why power prices may have hit a new plateau, and what it all means.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Bruce W. Radford</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - December 2000</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><blockquote><h1 align="center">Frontlines</h1>
<p align="center"></p>
<h1 align="center"> $$$/MWH???</h1>
<p align="center"></p>
<p align="center"> </p>
<p align="center"> </p>
<h3 align="left"> Why power prices may have hit a new plateau, and what it all means.</h3>
<p align="left"> <b>The gloves didn't really come off until just after lunch</b>, when Chairman James Hoecker returned at about 1:30 p.m. to take his center seat on the bench at the Federal Energy Regulatory Commission, to open the afternoon session at the FERC's umpteenth (and not last) hearing on last summer's troubles in California's electricity markets. </p>
<p align="left">First Hoecker asked for quiet. The lunch break had been way too short, leaving the audience edgy. Hoecker had let the morning session drag on nearly a full hour past its schedule, as he often does. </p>
<p align="left">Then the chairman fired up those newfangled and enormously expensive full-color flat-screen monitors placed strategically on either side of the hearing room, that give the FERC's hearing room a certain high-tech feel. Time to hear from California Gov. Gray Davis, who had chosen to mail in his testimony by videotape, rather than fly to Washington and explain in person why the feds owe it to his state to fix those skyrocketing prices. </p>
<p align="left">"You are asking us to knuckle under for the next 10 years or so," Davis warned, in a calm but convincing baritone. "You agree that the market is dysfunctional. </p>
<p align="left">You agree that prices are not just and reasonable. But you refuse to do anything about it. Apart from that, you are a fine group of people." </p>
<p align="left">At that point the entire room let loose with a laugh. All, that is, save onethat being the commissioner most likely to take over as FERC chairman under a new administration led by Texas Gov. Bush. I thought it odd. But California state Sen. Steve Peace, next up on the witness stand, had seen it too. </p>
<p align="left">"I note that [Commissioner Curt] Hébert didn't laugh at the governor's joke," said Peace as he opened up. </p>
<p align="left">"But that's OK," he continued, "because he [Gov. Gray] didn't mean to include the commissioner in his comment." </p>
<p align="left">And with that, Sen. Peace (a prime architect of California's power industry redesign) had opened the flood gates to a full afternoon of confrontation from state politicians, utilities, and especially the new independent power plant owners. This fight has caught Hoecker and his FERC entirely off guard. It promises to spiral way out of control. </p>
<p align="left"><b>"ARE WE IN A DIFFERENT PRICE PLATEAU TODAY THAN WHERE WE WERE A YEAR OF TWO AGO?"</b> In asking that question, California Power Exchange CEO George Sladoje suggests that "something happened in May 2000," and that prices "haven't been the same since." </p>
<p align="left">From Southern California Edison, senior vice president John Fielder (regulatory policy and affairs) questioned why wholesale power prices should remain so high as they have on into autumn, especially during off-peak periods. </p>
<p align="left">"There was no reason why the price yesterday (Nov. 8) at 8 p.m. was $147/MWh [14.7 cents per kWh]. That is just unconscionable." </p>
<p align="left">Nevertheless, Dynegy believes that the industry must learn to accept prices like that as normal. </p>
<p align="left">"Short-run marginal costs in California often exceed $100/MWh. With delivered gas costs running at approximately $7/MMBtu [equivalent to $70/MWh at a heat rate of 10,000Btu/kWh] and NO<sub>x </sub>emissions allowances in the Los Angeles basin running approximately $40-45/lb., these two categories of variable costs alone would total approximately $77-$148/MWh, depending on the efficiency of the generating unit." </p>
<p align="left">Adds Dynegy, "The commission should carefully consider the very real possibility that the rise in prices actually reflects an efficient, market-driven outcome." Such talk has spawned a race among utilities to calculate and present to the FERC a "just and reasonable" power price for a simple-cycle peaking gas turbine, based on typical costs for financing, fuel, and emissions credits, plus a reasonable return on equity.</p>
<p align="left"> In fact, it seems that forward markets for next summer already are showing about $140/MWh. They come down to $50-$55/MWh about four to five years out, but California's electric utilities say they won't commit that far in the future because according to state rules, they are immunized against a prudence review for forward purchases from the PX only out so far as March 2002 (i.e., 18 months). Meanwhile, Edison is bleeding money. </p>
<p align="left">"This is a matter of life and death for us," says Fielder. "Our undercollections are $2.5 billion. We added another $100 million last month. We are reducing employment." </p>
<p align="left">And at PG&amp;E, vice president (regulatory relations) Dede Hapner sees no net gain even in hedging against local California prices, since prices are rising all across the West. </p>
<p align="left">"Even if PG&amp;E ... bids $50 per MWh, and submits that bid to the PX as a scheduling coordinator, that bid may go out of state and then come back in. We need to untangle the web," she said, "and put the dollars back where they belong."</p>
<p align="left"><b>"THINK OF YOURSELF AS THE ALAN GREENSPAN OF THE CALIFORNIA MARKET. YOU NEED TO CURB THE IRRATIONAL EXUBERANCE."</b> That came from Diane Jacob, the chairwoman of the San Diego County Board of Supervisors. </p>
<p align="left">"There's no business that wants to come out to San Diego right now," she warned. "We have started studying the feasibility of starting a municipal electric utility." </p>
<p align="left">More threats came from Debra Brown, chairwoman of the state Senate's Energy, Utilities, and Communications Committee. </p>
<p align="left">"If another Prop 9 goes on the ballot again and if the populace sees that the generators are opposing it, then they will vote for it," predicted Brown. </p>
<p align="left">Sen. Peace then raised the ante, suggesting the state could take its $7 billion tax surplus and simply buy up the state's entire electric utility industry. </p>
<p align="left">"Our fear is your fear," warned Peace. "You will see a ballot initiative in 2002 to take the entire ... industry public. ... That would put the majority of generating capacity out West under public ownership [and] outside FERC authority. Where's your RTO plan then?" </p>
<p align="left">And that's hitting where it hurts. You could just see the FERC commissioners stiffen. </p>
<p align="left">In fact, of the 20-30 witnesses who testified before the commission on Nov. 9, not one suggested that grid access or congestion had anything to do with last summer's price spikes in California. In written comments filed Oct. 26, Dynegy explained why transmission markets played no meaningful role, despite arguments (convincing, I think) that the state should move to nodal-based, locational marginal pricing. </p>
<p align="left">"During the past 12 months total congestion costs (only a fraction of which is being uplifted) were just $211 million in a $26 billion market (about eight-tenths of 1 percent). Even if the current zonal structure needs work, price signals sent by LMP would have done nothing to hide the underlying problem with supply-demand imbalance." </p>
<p align="left">So far federal and state regulators have bet everything on transmission accessthat with enough regional transmission organizations to ensure a smooth flowing grid without discrimination by price or access, that electricity competition will flourish. But now comes the call to cap wholesale power prices, which would put FERC in the business of setting a rate base for every single power plant. </p>
<p align="left">Fifty years ago we tried to do the same thing for natural gas, when the Supreme Court's Phillips decision sent the Federal Power Commission (the FERC's ancestor) on a wild goose chase to regulate natural gas prices at the wellhead by production cost. All that did is nearly kill off the natural gas industry for some 30 years. </p>
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<a href="/tags/commission">Commission</a><span class="pur_comma">, </span><a href="/tags/communication">Communication</a><span class="pur_comma">, </span><a href="/tags/dynegy">Dynegy</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission">Federal Energy Regulatory Commission</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/han">HAN</a><span class="pur_comma">, </span><a href="/tags/ice">ICE</a><span class="pur_comma">, </span><a href="/tags/irr">IRR</a><span class="pur_comma">, </span><a href="/tags/lmp">LMP</a><span class="pur_comma">, </span><a href="/tags/nee">NEE</a><span class="pur_comma">, </span><a href="/tags/pge">PG&amp;E</a><span class="pur_comma">, </span><a href="/tags/rto">RTO</a><span class="pur_comma">, </span><a href="/tags/san-diego-county">San Diego County</a><span class="pur_comma">, </span><a href="/tags/think">THINK</a><span class="pur_comma">, </span><a href="/tags/urs">URS</a> </div>
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